Controlling fluid flow through a wellbore tubular

ABSTRACT

A wellbore flow control system includes a production tubular member configured to run into a wellbore formed from a terranean surface and into a subterranean formation; a plurality of autonomous inflow control valves (AICVs) positioned on the production tubular member, each of the plurality of AICVs controllable based at least in part on at least one of a density or a viscosity of a formation fluid; and a plurality of sliding sleeves mounted in the production tubular member, each of the plurality of sliding sleeves mounted near a set of AICVs of the plurality of AICVs, each of the plurality of sliding sleeves controllable based on a wellbore drawdown pressure to fluidly couple or fluidly decouple an inner volume of the production tubular member with the subterranean formation through the particular set of AICVs.

TECHNICAL FIELD

The present disclosure describes apparatus, systems, and methods for controlling fluid flow through a wellbore tubular.

BACKGROUND

Inflow control devices are often used in hydrocarbon production operations. For example, inflow control devices can be positioned within a wellbore and operated to open and close to, for instance, limit an amount of water from a subterranean formation (along with one or more hydrocarbons) that is produced to the surface.

SUMMARY

In an example implementation, a wellbore flow control system includes a production tubular member configured to run into a wellbore formed from a terranean surface and into a subterranean formation; a plurality of autonomous inflow control valves (AICVs) positioned on the production tubular member, each of the plurality of AICVs controllable based at least in part on at least one of a density or a viscosity of a formation fluid; and a plurality of sliding sleeves mounted in the production tubular member, each of the plurality of sliding sleeves mounted near a set of AICVs of the plurality of AICVs, each of the plurality of sliding sleeves controllable based on a wellbore drawdown pressure to fluidly couple or fluidly decouple an inner volume of the production tubular member with the subterranean formation through the particular set of AICVs.

In an aspect combinable with the general implementation, the set of AICVs includes a single AICV or a pair of AICVs.

In another aspect combinable with any one of the previous aspects, each of the plurality of sliding sleeves is controllable based on the wellbore drawdown pressure to fluidly couple or fluidly decouple the inner volume of the production tubular member with the subterranean formation through one AICV of the pair of AICVs in the particular set of AICVs.

In another aspect combinable with any one of the previous aspects, the production tubular member includes a plurality of compartments, each compartment including a particular set of AICVs and at least one sliding sleeve of the plurality of sliding sleeves.

In another aspect combinable with any one of the previous aspects, a number of the plurality of compartments is based at least in part on a reservoir pressure of the subterranean formation and a target flow rate of the formation fluid through the plurality of AICVs.

In another aspect combinable with any one of the previous aspects, the wellbore drawdown pressure includes a difference between the reservoir pressure and a flowing bottomhole pressure of the wellbore.

Another aspect combinable with any one of the previous aspects further includes one or more packers positioned on the production tubular member.

In another aspect combinable with any one of the previous aspects, adjacent compartments of the plurality of compartments are fluidly separated by at least one packer of the plurality of packers.

Another aspect combinable with any one of the previous aspects further includes a plurality of screens, each screen mounted across one or more AICVs of the plurality of AICVs.

In another general implementation, a wellbore fluid flow control method includes operating a production tubular member run into a wellbore formed from a terranean surface and into a subterranean formation, the production tubular member including a plurality of autonomous inflow control valves (AICVs) and a plurality of sliding sleeves, at least one of the plurality of sliding sleeves in a closed position to fluidly decouple a first set of AICVs of the plurality of AICVs from the subterranean formation; determining a composition of a wellbore fluid flowing from the subterranean formation into the production tubular member through a second set of AICVs of the plurality of AICVs; based on the determined composition, autonomously modulating a second set of AICVs of the plurality of AICVs toward a closed position; determining a flowing bottomhole pressure; and based on the determined flowing bottomhole pressure being less than a desired value, adjusting the at least one sliding sleeve of the plurality of sliding sleeves towards an open position to fluidly couple the production tubular member to the subterranean formation through the first set of AICVs.

In an aspect combinable with the general implementation, autonomously modulating the first set of AICVs of the plurality of AICVs toward the open position includes autonomously modulating one or two AICVs of the plurality of AICVs toward the open position.

In another aspect combinable with any one of the previous aspects, the production tubular member includes a plurality of compartments, each compartment including a particular set of AICVs and at least one sliding sleeve of the plurality of sliding sleeves.

In another aspect combinable with any one of the previous aspects, the first set of AICVS comprises a pair of AICVs.

In another aspect combinable with any one of the previous aspects, adjusting the at least one sliding sleeve of the plurality of sliding sleeves towards the open position to fluidly couple the production tubular member to the subterranean formation through the first set of AICVs includes adjusting the at least one sliding sleeve of the plurality of sliding sleeves towards the open position to fluidly couple the production tubular member to the subterranean formation through one AICV of the pair of AICVs of the first set of AICVs.

In another aspect combinable with any one of the previous aspects, the first set of AICVs is positioned in a first compartment and the second set of AICVs positioned in a second compartment.

In another aspect combinable with any one of the previous aspects, a number of the plurality of compartments is based at least in part on a reservoir pressure of the subterranean formation and a target flow rate of the formation fluid through the plurality of AICVs.

Another aspect combinable with any one of the previous aspects further includes fluidly isolating the first compartment from the second compartment within an annulus between the production tubular member and the subterranean formation by at least one packer positioned on the production tubular member.

Another aspect combinable with any one of the previous aspects further includes hydraulically actuating the at least one packer positioned on the production tubular member to fluidly isolate the first compartment from the second compartment.

Another aspect combinable with any one of the previous aspects further includes re-determining the flowing bottomhole pressure; and based on the re-determined flowing bottomhole pressure being less than a desired value, adjusting at least another sliding sleeve of the plurality of sliding sleeves toward the open position to fluidly couple the production tubular member to the subterranean formation through a third set of AICVs of the plurality of AICVs.

Another aspect combinable with any one of the previous aspects further includes screening the wellbore fluid flowing from the subterranean formation into the production tubular member through the second set of AICVs with a plurality of screens, each screen mounted across one or more AICVs of the second set of AICVs.

Another aspect combinable with any one of the previous aspects further includes running the production tubular member into the wellbore; and maintaining the at least one sliding sleeve in the closed position during the running.

Another aspect combinable with any one of the previous aspects further includes determining the flowing bottomhole pressure with a pressure sensor positioned at or near an entry of the wellbore; and measuring a flow rate of the wellbore fluid with a flowmeter positioned at or near the entry of the wellbore.

In another aspect combinable with any one of the previous aspects, determining the composition of the wellbore fluid flowing from the subterranean formation into the production tubular member through the second set of AICVs includes determining the composition of the wellbore fluid based on at least one of the viscosity or density.

In another aspect combinable with any one of the previous aspects, determining the composition of the wellbore fluid flowing from the subterranean formation into the production tubular member through the second set of AICVs includes determining the composition of the wellbore fluid at the second set of AICVs.

Implementations of a tubular flow control system according to the present disclosure may include one or more of the following features. For example, a tubular flow control system according to the present disclosure can prolong a life of a hydrocarbon well. As another example, a tubular flow control system according to the present disclosure can maximize dry oil and/or gas production. As a further example, a tubular flow control system according to the present disclosure can reduce costs by enhancing well performance without requiring rig intervention.

The details of one or more implementations of the subject matter described in this disclosure are set forth in the accompanying drawings and the description below. Other features, aspects, and advantages of the subject matter will become apparent from the description, the drawings, and the claims.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic diagram of an example implementation of a downhole flow control system according to the present disclosure.

FIG. 2 is a schematic diagram of an example implementation of a downhole flow control tubular according to the present disclosure.

FIG. 3 is a flowchart of an example method performed with or by an example implementation of a downhole flow control system according to the present disclosure.

FIG. 4 is a schematic illustration of an example controller (or control system) for operating a downhole flow control system according to the present disclosure.

DETAILED DESCRIPTION

The present disclosure describes example implementations of a downhole flow control system that includes autonomous inflow control valves (AICVs) and sliding sleeves that operate in combination to control a flow of a wellbore fluid from a subterranean formation (also called a reservoir) into a production tubular for production at a terranean surface. In some aspects, the downhole flow control system includes a tubular member or section that may be part of or coupled to a wellbore tubular, such as a production tubing or casing. The tubular member includes, in some aspects, one or more AICVs and at least one sliding sleeve in a particular compartment of the tubular member. In some aspects, the tubular member can include multiple compartments.

FIG. 1 is a schematic diagram of an example implementation of a downhole flow control system 100 according to the present disclosure. As illustrated, a wellbore 104 is formed (for example, drilled or otherwise) from a terranean surface 102 and into and through a subterranean formation 118. Although the terranean surface 102 is illustrated as a land surface, terranean surface 102 may be a sub-sea or other underwater surface, such as a lake or an ocean floor or other surface under a body of water. Thus, the present disclosure contemplates that the wellbore 104 may be formed under a body of water from a drilling location on or proximate the body of water.

The illustrated wellbore 104, in this example, is a directional wellbore. For instance, the wellbore 104 includes a substantially vertical portion 106 coupled to a radiused or curved portion 108, which in turn is coupled to a substantially horizontal portion 110. As used in the present disclosure, “substantially” in the context of a wellbore orientation, refers to wellbores that may not be exactly vertical (for example, exactly perpendicular to the terranean surface 102) or exactly horizontal (for example, exactly parallel to the terranean surface 102). In other words, those of ordinary skill in the drill arts would recognize that vertical wellbores often undulate offset from a true vertical direction, that they might be drilled at an angle that deviates from true vertical, and horizontal wellbores often undulate offset from a true horizontal direction. Further, the substantially horizontal portion 110, in some aspects, may be a slant wellbore or other directional wellbore that is oriented between exactly vertical and exactly horizontal. Further, the substantially horizontal portion 110, in some aspects, may be a slant wellbore or other directional well bore that is oriented to follow the slant of the formation 118. As illustrated in this example, the three portions of the wellbore 104—the vertical portion 106, the radiused portion 108, and the horizontal portion 110—form a continuous wellbore 104 that extends into the Earth.

In this example, the illustrated wellbore 104 has a surface casing 120 positioned and set around the wellbore 104 from the terranean surface 102 into a particular depth in the Earth. For example, the surface casing 120 may be a relatively large-diameter tubular member (or string of members) set (for example, cemented) around the wellbore 104 in a shallow formation. As used herein, “tubular” may refer to a member that has a circular cross-section, elliptical cross-section, or other shaped cross-section.

As illustrated, a production casing 122 is positioned and set within the wellbore 104 downhole of the surface casing 120. Although termed a “production” casing, in this example, the casing 122 may include any casing installed in the wellbore 104 that subject to hydrocarbon production operations, such as, for example, perforating operations, hydraulic fracturing operations, or production operations (or a combination thereof). Thus, the casing 122 refers to and includes any form of tubular member that is set (for example, cemented) in the wellbore 104 downhole of the surface casing 120. In some examples, the production casing 122 may begin at an end of the radiused portion 108 and extend throughout the substantially horizontal portion 110. The casing 122 could also extend into the radiused portion 108 and into the vertical portion 106.

As shown, cement 130 is positioned (for example, pumped) around the casings 120 and 122 in an annulus between the casings 120 and 122 and the wellbore 104. The cement 130, for example, may secure the casings 120 and 122 (and any other casings or liners of the wellbore 104) through the subterranean formations (including subterranean formation 118) under the terranean surface 102. In some aspects, the cement 130 may be installed along the entire length of the casings (for example, casings 120 and 122 and any other casings), or the cement 130 could be used along certain portions of the casings if adequate for a particular wellbore 104.

The wellbore 104 and associated casings 120 and 122 may be formed with various example dimensions and at various example depths (for example, true vertical depth, or TVD). For instance, a conductor casing (not shown) may extend down to about 120 feet TVD, with a diameter of between about 28 in. and 60 in. The surface casing 120 may extend down to about 2500 feet TVD, with a diameter of between about 22 in. and 48 in. An intermediate casing (not shown) between the surface casing 120 and production casing 122 may extend down to about 8000 feet TVD, with a diameter of between about 16 in. and 36 in. The production casing 122 may extend substantially horizontally (for example, to case the substantially horizontal portion 110) with a diameter of between about 11 in. and 22 in. The foregoing dimensions are merely provided as examples and other dimensions (for example, diameters, TVDs, lengths) are contemplated by the present disclosure. For example, diameters and TVDs may depend on the particular geological composition of one or more of multiple subterranean formations (including formation 118), particular drilling techniques, or particular secondary operation techniques (for example, perforating, fracturing, acid jobs, fluid injection from other wellbores, and otherwise).

As shown in this example, the downhole flow control system 100 includes a wellbore tubular 124, for example, a production tubing or otherwise, that extends into the wellbore 104 from the terranean surface 102. Coupled to or part of the wellbore tubular 124 is a production tubular member (or section) 125. In some aspects, the production tubular member 125 is a single-piece downhole tool (tubular) that includes one or more AICVs, one or more sliding sleeves, and one or more wellbore seals (for example, packers) as described herein and can be coupled (for example, threadingly or otherwise) to the wellbore tubular 124. In some aspects, the production tubular member 125 comprises multiple tubular sections coupled together (for example, threadingly). Each tubular section of the tubular member 125 may comprise one or more AICVs, one or more sliding sleeves, and one or more wellbore seals (for example, packers) as described herein.

As shown in this example, the tubular member 125 includes or is separated into multiple compartments 138 a-138 c as shown in FIG. 1. Each compartment 138 a-138 c may include one or more AICVs and at least one sliding sleeve. In some aspects, each compartment 138 a-138 c is fluidly isolated (for example, within an annulus volume between the tubular member 125 and the casing 122) from other compartments 138 a-138 c by at least one wellbore seal 132, such as a packer 132 (for example, hydraulically or mechanically actuated packer). For example, as shown in FIG. 1, the compartment 138 a includes (two) AICVs 134 a and the sliding sleeve 136 a; the compartment 138 b includes (two) AICVs 134 b and the sliding sleeve 136 b; and the compartment 138 c includes (two) AICVs 134 c and the sliding sleeve 136 c. Other example implementations of the tubular member 125 can include more or fewer compartments; further, other example implementations of each compartment 138 a-138 c can include more or fewer AICVs.

In some aspects, the tubular member 125 can control wellbore water production from the subterranean formation 118 into the wellbore tubular 124, as well as wellbore drawdown, by operating (in combination) the illustrated AICVs with the illustrated sliding sleeves (for example, on a compartment-by-compartment basis). For example, each of the AICVs 134 a-134 c can be controlled (for example, to open, to close, or to be positioned between 100% open and 100% closed) autonomously. For example, the AICVs 134 a-134 c can operate to autonomously (for example, without direction or control external to the valves), distinguish between hydrocarbons and undesired fluids (for example, water) within a produced flow into the AICVs 134 a-134 c. When the produced fluids are 100% hydrocarbons, the AICVs 134 a-134 c autonomously operate at 100% open. On the other hand, the AICVs 134 a-134 c are autonomously operated to close or partially close based on a particular percentage of undesired fluid/gas passing through the AICVs 134 a-134 c. Thus, the tubular member 125 allows selective activation of each AICV (or set of AICVs in a compartment) based on watercut without a need for rig intervention. In some aspects, watercut is determined by a density, a viscosity, or both, of the wellbore fluid.

As one or more AICVs 134 a-134 c (or sets of AICVs for more than one AICV per compartment) are adjusted, wellbore drawdown can be changed. In some aspects according to the present disclosure, wellbore drawdown is a pressure difference in a reservoir pressure (for example, pressure of the subterranean formation 118) and a flowing bottomhole pressure (for example, a pressure within and at a downhole end of the wellbore 104 during production of the wellbore fluid). As watercut increases (and one or more AICVs 134 a-134 c or sets of AICVs are closed), an increasing amount of a wellbore fluid production flows through remaining open (or at least partially open) AICVs in particular compartments 138 a-138 c in the tubular member 125. Such compartments 138 a-138 c may therefore being to be “dry” (in other words, with less and less watercut), which will increase wellbore drawdown in the dry compartments 138 a-138 c. This can lower overall well production of hydrocarbons.

The example tubular member 125 can activate one or more of the sliding sleeves 136 a-136 c (for example, based on measurements from one or more sensors in a sensor system 146) to increase wellbore fluid production into the wellbore tubular 124 as the flowing bottom-hole pressure decreases below a particular threshold. Thus, well productivity can increase and wellbore drawdown can decrease in a rigless operation (in other words, rigless intervention) with the tubular member 125.

FIG. 2 is a schematic diagram of an example implementation of a downhole flow control tubular 200 according to the present disclosure. In some aspects, the flow control tubular 200 can be used as or in place of the tubular member 125 shown in FIG. 1. As shown in FIG. 2, the flow control tubular 200 is positioned in a portion of a wellbore 201 that is formed in a reservoir 203. In this example, the flow control tubular 200 a tubing 202 with an interior volume 206. An annulus 204 is formed between the wellbore 201 and the tubing 202.

As shown in this example, the flow control tubular 200 includes or is separated into multiple compartments 208 a-208 c. Each compartment 208 a-208 c may include one or more AICVs and at least one sliding sleeve. As shown, each compartment 208 a-208 c is fluidly isolated (for example, within the annulus 204 between the tubing 202 and the wellbore 201) from other compartments 208 a-208 c by at least one packer 211 (for example, a hydraulically or mechanically actuated packer). In this example, each compartment 208 a-208 c includes two AICVs 210 a and a sliding sleeve 212. Other example implementations of the flow control tubular 200 can include more or fewer compartments; further, other example implementations of each compartment 208 a-208 c can include more or fewer AICVs 210 or more sliding sleeves 212.

As further shown in FIG. 2, each compartment 208 a-208 c include a screen 214 that circumscribes the tubing 202 around each AICV 210. The screen 214, in some aspects, can filter fluid particulates in the wellbore fluid 215 from entering the interior volume 206 of the tubing 202 through the AICVs 210.

In this example, each sliding sleeve 212 is moveable (for example, by coiled tubing) to fluidly decouple the annulus 204 from the interior volume 206 through one or both AICVs 210 of each compartment 208 a-208 c to prevent (or substantially prevent) a wellbore fluid (or production flow) 215 from entering the tubing 202 from one or more perforations or fractures in the reservoir 203 (and casing, not shown). In some aspects, each sliding sleeve 212 is moveable (to fully or partially cover or uncover one or more AICVs within a particular compartment), for example by coiled tubing. Independently of control of the sliding sleeves 212, each AICV 210 is autonomously controllable to adjust to a fully open position, a fully closed position, or a partially open position.

In some aspects, the flow control tubular 200 can be installed initially with one or more of the sliding sleeves 212 in a closed position (fluidly decoupling one or more AICVs 210 from the reservoir 203). At an initial stage, production flow 215 is passing through the other AICVs (for fluidly decoupled) only. As production continues, the undesirable fluid/gas percentage passed through the AICVs 210 that are not fluidly decoupled by a sliding sleeve 112 can increase, resulting in autonomous closure (for example, partial or full) the open AICVs 210. The flowing bottomhole pressure is thus lowered, thereby increasing drawdown due to less flow area into the flow control tubular 200. This decrease in flowing bottomhole pressure can ultimately result in lowering the flowrate of the production fluid 215 into the flow control tubular 200. Once this pressure decreases below a particular threshold, one or more of the sliding sleeves 112 can be mechanically opened (for example, riglessly using a coiled tubing unit). This intervention by opening one or more of the previously closed sliding sleeves 112 can therefore fluidly couple two or more AICVs 210 to the reservoir 203 to restore well productivity by increasing the flow area (leading to higher flowing bottomhole pressure and lower drawdown).

FIG. 3 is a flowchart of an example method 300 performed with or by an example implementation of a downhole flow control system according to the present disclosure. For example, method 300 may be executed with or by the downhole flow control system 100 (including the tubular member 125 or the flow control tubular 200). Method 300 can begin at step 302, which includes operating a production tubular member (within a wellbore) that includes a plurality of autonomous inflow control valves (AICVs) and a plurality of sliding sleeves. At least one of the sliding sleeves is positioned to fluidly decouple a first set (one or more) of AICVs of the plurality of AICVs from a reservoir. For example, a downhole tool (for example, tubular member 125 or flow control tubular 200) can be run into a wellbore as part of or coupled to a wellbore tubular, such as a production tubular. In some aspects, the wellbore can include a casing that has previously been perforated and, in some cases, fractured. Alternatively, the wellbore may be an open hole completion. The production tubular member can be defined by or include multiple compartments, where each of the compartments includes one or more (such as a set of) AICVs and a sliding sleeve (for example, mechanically operated).

In some aspects, one or more packers are included with or coupled to the production tubular member and actuated to fluidly separate the compartments in an annulus between the production tubular member and the subterranean formation (or casing). In some aspects, while the production tubular member is initially operating (or running into the wellbore), each of the AICVs can be open and one or more of the sliding sleeves is in a closed position. In some aspects, the number of AICVs, the number of compartments, or the number of AICVs per compartment (or a combination thereof) may be determined and designed into the production tubular member based on, for instance, an expected or measure reservoir pressure, an expected or desired inflow rate of the wellbore fluid, or a combination thereof.

Method 300 can continue at step 304, which includes flowing a wellbore fluid from the reservoir through a second set of AICVs and into the production tubular. The second set of AICVs, therefore, is fluidly coupled to the reservoir without being closed by one or more of the sliding sleeves. For example, during a normal operation of the production tubular member, the AICVs in the second set (or sets other than the first set, with each set of AICVS positioned in a particular compartment of the production tubular member) are open (for example, 100% open) to allow a wellbore fluid (for example, a mixture of hydrocarbon fluids and water) to flow from the reservoir, into the annulus, through the set of open AICVs, and into an interior volume of the production tubular member. During step 304, the sliding sleeves can be positioned so as to allow fluid flow through the second set of AICVs without impedance. In some aspects, a screen may be positioned in each compartment of the production tubular member to catch or filter particulates from the wellbore fluid as it enters the interior volume.

Method 300 can continue at step 306, which includes determining a composition of the wellbore fluid. For example, in some aspects, one or more sensors (of the AICVs) can operate to determine one or more properties of the wellbore fluid to determine the composition. Also, there can be a pressure sensor to determine a flowing bottomhole pressure and a flowmeter to determine a flow rate of the produced fluids (included in the sensor system 146). In some aspects, such properties, such as viscosity, density, or both, can determine a composition, and therefore, a watercut of the wellbore fluid.

Method 300 can continue at step 308, which includes a determination of whether the composition of the wellbore fluid indicates a high watercut. In some aspects, this step is performed autonomously by the AICVs on a valve-by-valve basis. For example, if the watercut (as determined by the composition) is low (below a threshold value), then step 308 may continue back to step 304 for normal operation (for example, with the second set of AICVs fully open). In some aspects, the property (and watercut) can be determined on a compartment-by-compartment basis. If the watercut is above a desired value (according to the composition) in one or more of the compartments, then the method can continue to step 310.

Step 310 includes modulating the second set of AICVs of the plurality of AICVs toward a closed position. As in step 308, this step is performed autonomously by the second set of AICVs, for example, on a valve-by-valve basis. For example, based on the determined watercut being too high in 308, the second set (one or more) of AICVs in the production tubular member may be autonomously adjusted toward a closed position. In some aspects, only the set of AICVs within the particular compartment in which the watercut was determined to be too high is autonomously modulated toward or to the closed position.

Method 300 can continue at step 312, which includes flowing a wellbore fluid from a reservoir through the modulated second set of AICVs and into the production tubular. For example, once the second set of AICVs is adjusted in step 310, operation of the production tubular member to receive the wellbore fluid can continue. Wellbore fluid received into the production tubular through open AICVs (all or partially) can be circulated to the terranean surface.

Method 300 can continue at step 314, which includes determining a Flowing bottomhole pressure. For example, one or more pressure sensors can determine a differential between the reservoir pressure and the bottomhole pressure in the wellbore (for example, during step 312). For example, after producing a wellbore fluid from a well for a time period (as in step 304), a percentage of undesired fluid can increase in some of the compartments of the production tubular member. Thus, some restriction or full closure of the second set of AICVs (as in step 310) can occur, which can minimize production from these compartments in which one or more AICVs were closed. Execution of step 310, therefore, can result in creating a higher wellbore drawdown across the other compartments to meet a target wellbore fluid flowrate into the production tubular member. As a wellbore drawdown increases, the flowing bottom hole pressure can reach a minimum operating limit and the target rate will not be achieved.

Thus, method 300 can continue at step 316, which includes a determination of whether the Flowing bottomhole pressure is less than a threshold value. For example, if the determination is no and the flowing bottomhole pressure is greater than the threshold value (thereby signifying an acceptable production rate of the wellbore fluid), then method 300 can revert back to step 312.

If the determination in step 316 is yes, then method 300 can continue at step 318, which includes adjusting the sliding sleeve toward an open position to fluidly couple the production tubular member from the subterranean formation through the first set of AICVs. For example, in a compartment in which the AICVs are fluidly decoupled from the reservoir due to position of the sliding sleeve, the sliding sleeve can be adjusted to increase or start flow of the wellbore fluid into that compartment by uncovering the set (one or more) of the AICVs in that compartment (in other words, fluidly coupling that compartment to the reservoir).

In some aspects, step 318 includes adjusting the sliding sleeve toward the open position to fluidly couple the production tubular member from the subterranean formation through a number of AICVs less than the full set of AICVs in the first set of AICVs. For example, the first set of AICVs can include a pair of AICVs. In some aspects, during the operation of the production tubular member (for example, in step 304), a first AICV of the pair of AICVs is fluidly decoupled (by the sliding sleeve) from the subterranean formation, while a second AICV of the pair of AICVs is fluidly coupled to the subterranean formation. Step 318 can include, therefore, adjusting the sliding sleeve to fluidly couple the first AICV to the subterranean formation, thereby facilitating flow of fluid through both the first and second AICVs of the first set of AICVs.

Method 300 can continue at step 320, which includes flowing the wellbore fluid from the reservoir through the first set of AICVs (now uncovered by the adjusted sliding sleeve) and into the production tubular. For example, after adjusting the sliding sleeve in one or more compartments, operation of flowing the wellbore fluid into the production tubular member (at an increased flowing bottomhole pressure) can continue.

While this specification contains many specific implementation details, these should not be construed as limitations on the scope of any inventions or of what may be claimed, but rather as descriptions of features specific to particular implementations of particular inventions. Certain features that are described in this specification in the context of separate implementations can also be implemented in combination in a single implementation. Conversely, various features that are described in the context of a single implementation can also be implemented in multiple implementations separately or in any suitable subcombination. Moreover, although features may be described above as acting in certain combinations and even initially claimed as such, one or more features from a claimed combination can in some cases be excised from the combination, and the claimed combination may be directed to a subcombination or variation of a subcombination.

Similarly, while operations are depicted in the drawings in a particular order, this should not be understood as requiring that such operations be performed in the particular order shown or in sequential order, or that all illustrated operations be performed, to achieve desirable results. In certain circumstances, multitasking and parallel processing may be advantageous. Moreover, the separation of various system components in the implementations described above should not be understood as requiring such separation in all implementations, and it should be understood that the described program components and systems can generally be integrated together in a single software product or packaged into multiple software products.

A number of implementations have been described. Nevertheless, it will be understood that various modifications may be made without departing from the spirit and scope of the disclosure. For example, example operations, methods, or processes described herein may include more steps or fewer steps than those described. Further, the steps in such example operations, methods, or processes may be performed in different successions than that described or illustrated in the figures. Accordingly, other implementations are within the scope of the following claims. 

What is claimed is:
 1. A wellbore flow control system, comprising: a production tubular member configured to run into a wellbore formed from a terranean surface and into a subterranean formation; a plurality of autonomous inflow control valves (AICVs) positioned on the production tubular member, each of the plurality of AICVs controllable based at least in part on at least one of a density or a viscosity of a formation fluid; and a plurality of sliding sleeves mounted in the production tubular member, each of the plurality of sliding sleeves mounted near a set of AICVs of the plurality of AICVs, each of the plurality of sliding sleeves controllable based on a wellbore drawdown pressure to fluidly couple or fluidly decouple an inner volume of the production tubular member with the subterranean formation through at least one of the particular set of AICVs.
 2. The wellbore flow control system of claim 1, wherein the set of AICVs comprises a single AICV or a pair of AICVs.
 3. The wellbore flow control system of claim 2, wherein each of the plurality of sliding sleeves is controllable based on the wellbore drawdown pressure to fluidly couple or fluidly decouple the inner volume of the production tubular member with the subterranean formation through one AICV of the pair of AICVs in the particular set of AICVs.
 4. The wellbore flow control system of claim 1, wherein the production tubular member comprises a plurality of compartments, each compartment comprising a particular set of AICVs and at least one sliding sleeve of the plurality of sliding sleeves.
 5. The wellbore flow control system of claim 4, wherein a number of the plurality of compartments is based at least in part on a reservoir pressure of the subterranean formation and a target flow rate of the formation fluid through the plurality of AICVs.
 6. The wellbore flow control system of claim 5, wherein the wellbore drawdown pressure comprises a difference between the reservoir pressure and a flowing bottomhole pressure of the wellbore.
 7. The wellbore flow control system of claim 4, further comprising one or more packers positioned on the production tubular member.
 8. The wellbore flow control system of claim 7, wherein adjacent compartments of the plurality of compartments are fluidly separated by at least one packer of the plurality of packers.
 9. The wellbore flow control system of claim 1, further comprising a plurality of screens, each screen mounted across one or more AICVs of the plurality of AICVs.
 10. A wellbore fluid flow control method, comprising: operating a production tubular member run into a wellbore formed from a terranean surface and into a subterranean formation, the production tubular member comprising a plurality of autonomous inflow control valves (AICVs) and a plurality of sliding sleeves, at least one of the plurality of sliding sleeves in a closed position to fluidly decouple a first set of AICVs of the plurality of AICVs from the subterranean formation; determining a composition of a wellbore fluid flowing from the subterranean formation into the production tubular member through a second set of AICVs of the plurality of AICVs; based on the determined composition, autonomously modulating a second set of AICVs of the plurality of AICVs toward a closed position; determining a flowing bottomhole pressure; and based on the determined flowing bottomhole pressure being less than a desired value, adjusting the at least one sliding sleeve of the plurality of sliding sleeves towards an open position to fluidly couple the production tubular member to the subterranean formation through at least one of the first set of AICVs.
 11. The method of claim 10, wherein autonomously modulating the first set of AICVs of the plurality of AICVs toward the open position comprises autonomously modulating one or two AICVs of the plurality of AICVs toward the open position.
 12. The method of claim 10, wherein the production tubular member comprises a plurality of compartments, each compartment comprising a particular set of AICVs and at least one sliding sleeve of the plurality of sliding sleeves, the first set of AICVs positioned in a first compartment and the second set of AICVs positioned in a second compartment.
 13. The method of claim 12, wherein the first set of AICVS comprises a pair of AICVs, and adjusting the at least one sliding sleeve of the plurality of sliding sleeves towards the open position to fluidly couple the production tubular member to the subterranean formation through the first set of AICVs comprises: adjusting the at least one sliding sleeve of the plurality of sliding sleeves towards the open position to fluidly couple the production tubular member to the subterranean formation through one AICV of the pair of AICVs of the first set of AICVs.
 14. The method of claim 12, wherein a number of the plurality of compartments is based at least in part on a reservoir pressure of the subterranean formation and a target flow rate of the formation fluid through the plurality of AICVs.
 15. The method of claim 12, further comprising fluidly isolating the first compartment from the second compartment within an annulus between the production tubular member and the subterranean formation by at least one packer positioned on the production tubular member.
 16. The method of claim 15, further comprising hydraulically actuating the at least one packer positioned on the production tubular member to fluidly isolate the first compartment from the second compartment.
 17. The method of claim 10, further comprising: re-determining the flowing bottomhole pressure; and based on the re-determined flowing bottomhole pressure being less than a desired value, adjusting at least another sliding sleeve of the plurality of sliding sleeves toward the open position to fluidly couple the production tubular member to the subterranean formation through a third set of AICVs of the plurality of AICVs.
 18. The method of claim 10, further comprising screening the wellbore fluid flowing from the subterranean formation into the production tubular member through the second set of AICVs with a plurality of screens, each screen mounted across one or more AICVs of the second set of AICVs.
 19. The method of claim 10, further comprising: running the production tubular member into the wellbore; and maintaining the at least one sliding sleeve in the closed position during the running.
 20. The method of claim 10, further comprising: determining the flowing bottomhole pressure with a pressure sensor positioned at or near an entry of the wellbore; and measuring a flow rate of the wellbore fluid with a flowmeter positioned at or near the entry of the wellbore.
 21. The method of claim 10, wherein determining the composition of the wellbore fluid flowing from the subterranean formation into the production tubular member through the second set of AICVs comprises determining the composition of the wellbore fluid based on at least one of the viscosity or density.
 22. The method of claim 21, wherein determining the composition of the wellbore fluid flowing from the subterranean formation into the production tubular member through the second set of AICVs comprises determining the composition of the wellbore fluid at the second set of AICVs. 